Solid carbonaceous subterranean formations such as coal seams can contain significant quantities of natural gas. This natural gas is composed primarily of methane, typically between 90 and 95% by volume. The majority of the methane is adsorbed to the carbonaceous material of the formation. In addition to the methane, lesser amounts of other compounds such as water, nitrogen, carbon dioxide, and heavier hydrocarbons can be held within the carbonaceous matrix or adhered to its surface. The world-wide reserves of methane found within solid carbonaceous subterranean formations are huge, and therefore techniques have been developed to facilitate the recovery of methane from such formations.
Historically, the methane has been primarily recovered from solid carbonaceous subterranean formations by depleting the reservoir pressure. With pressure depletion methods, as the reservoir pressure of the solid carbonaceous subterranean formation is lowered, the partial pressure of methane within the cleats decreases. This causes methane to desorb from the methane sorption sites and diffuse to the cleats. Once within the cleat system, the methane flows to a recovery well where it is recovered. The reservoir pressure of the formation continually decreases as methane is recovered from the solid carbonaceous subterranean formation. Typically, the methane recovery rate decreases over time as the reservoir pressure of the formation decreases. For coal seams, it is believed that primary pressure depletion techniques are capable of economically producing about 35 to 70% of the original methane-in-place within a seam. The recovery rate of methane from such formations and the percentage of the original methane-in-place that can be recovered from a formation by using primary pressure depletion techniques is dependent on the reservoir properties of the formation.
Predicting the amount of methane contained in a solid carbonaceous subterranean formation, the expected methane recovery rate, and the percentage of methane which can be expected to be recovered from a formation is difficult, time consuming, and expensive. Typically, core samples are obtained from the formation of interest to determine the reservoir properties of the formation, including the amount of methane contained within the formation, and to determine the thickness and vertical placement of the carbonaceous material. Unfortunately, solid carbonaceous subterranean formations such as coal seams are often very heterogeneous and may exhibit a great deal of anisotropy in both the vertical and horizontal directions. Also, the carbonaceous material is often found in discrete bedding layers, which are often separated by shale or sandstone. Therefore, core samples often do not provide reliable estimates of the reservoir quality.
Full scale production pilots often are required to better delineate the methane recovery potential for a particular solid carbonaceous subterranean formation. A typical production pilot has several recovery wells which penetrate the solid carbonaceous subterranean formation. A production pilot which is used to delineate the recovery of methane from a solid carbonaceous subterranean formation by primary pressure depletion techniques can cost several million dollars and require several months or years to delineate the methane recovery potential from a particular solid carbonaceous subterranean formation.
Pressure fall-off tests have been used in the past to determine the wellbore skin, the reservoir permeability, and the reservoir pressure of the region of a coal seam surrounding a wellbore. In these types of tests, water is typically injected into the formation through an injection well. The injection is continued for the desired period of time and then the injection well is shut-in. During the period of time when the injection well is shut-in, the pressure in the wellbore is measured. The pressure fall-off data can be analyzed to provide the skin, permeability, and reservoir pressure. However, as discussed earlier, solid carbonaceous subterranean formations often exhibit a high degree of heterogeneity and anisotropy, which can not be determined from standard pressure fall-off tests. Therefore, standard pressure fall-off tests typically do not provide enough information to sufficiently describe the reservoir quality of a typical solid carbonaceous subterranean formation.
The recovery of methane using primary pressure depletion techniques may not be satisfactory for many solid carbonaceous subterranean formations. In order to improve the recovery of methane from solid carbonaceous subterranean formations, techniques have been developed which enable a larger percentage of the original methane-in-place to be recovered from such a formation and at a higher rate than could be attainable using pressure depletion techniques. One such technique utilizes an injected gaseous desorbing fluid, such as nitrogen, oxygen-depleted air, air, flue gas, or any other gas which contains at least 50% by volume nitrogen. The injected gaseous desorbing fluid reduces the partial pressure of methane in the cleats and causes methane to desorb from methane sorption sites into the cleats. Another such technique utilizes an injected gaseous desorbing fluid which contains at least 50% by volume carbon dioxide. The carbon dioxide contained in the fluid preferentially adsorbs to the methane sorption sites and thereby causes the methane to desorb from the sorption sites and diffuse into the cleats.
Once within the cleats, the methane moves toward a recovery well. Additional advantages occur from both the above techniques because the injected gaseous desorbing fluid tends to pressure up the formation, thereby allowing faster recovery of methane-in-place from a solid carbonaceous subterranean formation than with primary pressure depletion techniques. Also, the use of injected gaseous desorbing fluid allows a greater percentage of methane-in-place to be recovered than with primary pressure depletion techniques. The methods which utilize an injected gaseous desorbing fluid to enhance the recovery of methane from a solid carbonaceous subterranean formation are sometimes hereinafter referred to as "enhanced methane recovery techniques."
While the use of enhanced methane recovery techniques improve the recovery of methane from a formation, these techniques also require extensive design work and engineering. Further, the higher recovery rate and the additional methane-in-place which can be recovered using enhanced methane recovery techniques may not justify the additional cost associated with implementing the techniques on a particular formation.
In order to determine whether enhanced recovery techniques are appropriate for a particular solid carbonaceous subterranean formation, the recovery of methane from the formation using such techniques must be accurately predicted. Unfortunately, the reservoir characteristics determined from a typical pressure fall-off test alone will not provide enough information to accurately predict the recovery of methane which can be expected from a production project which utilizes enhanced methane recovery techniques. And, as with primary pressure depletion techniques, a full scale production pilot which utilizes enhanced methane recovery techniques can cost several million dollars and require months or years to complete.
What is desired is a method which can determine the reservoir quality of a solid carbonaceous subterranean formation. Additionally, what is desired is a relatively quick and inexpensive method which is capable of predicting the methane recovery rate and the percentage of the original methane-in-place which can be recovered from a solid carbonaceous subterranean formation using enhanced methane recovery techniques.
As used herein, the following terms shall have the following meanings:
(a) "air" refers to any gaseous mixture containing at least 15 volume percent oxygen and at least 60 volume percent nitrogen. "Air" is typically the atmospheric mixture of gases found at the well site and contains between about 20 and 22 volume percent oxygen and between about 78 and 80 volume percent nitrogen;
(b) "carbonaceous material" refers to the solid carbonaceous materials that are believed to be produced by the thermal and biogenic degradation of organic matter. The term carbonaceous material specifically excludes carbonates and other minerals which are believed to be produced by other types of processes;
(c) "characteristic residence flow time" is the time required for a molecule of a gaseous non-adsorbing fluid, such as helium, to travel through the cleat system of a solid carbonaceous subterranean formation from a point in the formation near an injection wellbore to a point in the formation near a recovery wellbore;
(d) "characteristic diffusion time" for a solid carbonaceous subterranean formation is the time required for 67% of a gaseous fluid to desorb or adsorb to the formation's carbonaceous matrix.
(e) "cleats" or "cleat system" is the natural system of fractures within a solid carbonaceous subterranean formation;
(f) a "coalbed" comprises one or more coal seams in fluid communication with each other;
(g) "coal seams" are carbonaceous formations which typically contain between 50 and 100 percent organic material by weight;
(h) the "effective permeability" is a measure of the resistance offered by a formation to the movement of gaseous fluids through it. Effective permeability will vary with different pore pressures and can vary by location within the formation. Effective permeability includes stress dependent permeability effects and relative permeability effects;
(i) the "effective permeability relationship" is a description of how the effective permeability varies with pore pressure and how it varies with the water saturation within the formation. This relationship is important since the pore pressure and the water saturation can change as gaseous desorbing fluid is injected into the formation;
(j) "flue gas" refers to the gaseous mixture which results from the combustion of a hydrocarbon with air. The exact chemical composition of flue gas depends on many variables, including but not limited to, the combusted hydrocarbon, the combustion process oxygen-to-fuel ratio, and the combustion temperature;
(k) "formation parting pressure" and "parting pressure" mean the pressure needed to open a formation and propagate an induced fracture through the formation;
(l) "fracture half-length" is the distance, measured along the fracture, from the wellbore to the fracture tip;
(m) "gaseous desorbing fluid" includes any fluid or mixture of fluids which is capable of causing methane to desorb from a solid carbonaceous subterranean formation;
(n) the "initial reservoir pressure" is the reservoir pressure which existed within the wellbore at the time of the original completion of the wellbore into the solid carbonaceous subterranean formation;
(o) "K.sub.i " is the effective permeability which existed within the formation at the initial reservoir pressure;
(p) "K.sub.f " is the effective permeability which exists within the formation for a given pore pressure;
(q) "pore pressure" is the pressure present within the pore spaces of the cleat system. The pore pressure can vary throughout the formation and can vary as fluids are injected into and withdrawn from the formation;
(r) "reservoir flow capacity" is a measure of the flow rate that can be achieved within a solid carbonaceous subterranean formation. The reservoir flow capacity is the product of the effective permeability times the height or thickness of the formation. For an injection wellbore, the reservoir flow capacity should take into account the stress dependent permeability relationship of the formation, since the effective permeability present within the near wellbore region will vary as the pore pressure within the near wellbore region changes during injection of gaseous desorbing fluid;
(s) "reservoir pressure" means the pressure at the face of the productive formation when the well is shut-in. The reservoir pressure can vary throughout the formation. Also, the reservoir pressure may change over time as fluids are produced from the formation and/or gaseous desorbing fluid is injected into the formation;
(t) "solid carbonaceous subterranean formation" refers to any substantially solid carbonaceous, methane-containing material located below the surface of the earth. It is believed that these methane containing materials are produced by the thermal and biogenic degradation of organic matter. Solid carbonaceous subterranean formations include but are not limited to coalbeds and other carbonaceous formations such as antrium, carbonaceous, and devonian shales;
(u) "sorption" refers to a process by which a gas is held by a carbonaceous material, such as coal, which contains micropores. The gas typically is held on the coal in a condensed or liquid-like phase within the micropores, or the gas may be chemically bound to the coal;
(v) "sweep" refers to the region of a formation contacted by a fluid introduced into the formation. The sweep of the formation is measured as a percentage of the formation contacted; The total sweep is the product of the sweep in the areal and vertical directions;
(w) "well spacing" or "spacing" is the straight-line distance between the Individual wellbores of two separate wells. The distance is measured from where the wellbores intercept the formation of interest;
(x) "wellbore skin" is a measure of the relative damage to the region of the formation surrounding the wellbore.